The discharge into the atmosphere of sulfur compounds during processing and end-use of petroleum products derived from sulfur-containing hydrocarbons, such as sour crude oil, poses health and environmental problems. As a result, strict new requirements for sulfur content of, e.g., fuel oils, have been introduced. These stringent, reduced sulfur specifications applicable to transportation and other-fuel products have impacted the refining industry, and it is necessary for refiners to make capital investments to greatly reduce the sulfur content in products, such as gas oils to 10 parts per million by weight (ppmw) or less. In industrialized nations such as the United States, Japan and the countries of the European Union, refineries are already required to produce environmentally clean transportation fuels. For instance, since 2007, the United States Environmental Protection Agency has required that the sulfur content of highway diesel fuel be reduced by 97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels to contain less than 10 ppmw of sulfur. Other countries are following in the footsteps of the United States and the European Union and are moving forward with regulations that will require refineries to produce transportation fuels with an ultra-low sulfur level.
To keep pace with recent trends toward production of ultra-low sulfur fuels, refiners must choose among processes or raw materials, such as oils which provide flexibility so that future specifications can be met with minimum additional capital investment, preferably, by utilizing existing equipment. Technologies such as hydrocracking and two-stage hydrotreating offer solutions to refiners for the production of clean transportation fuels. These technologies are available and can be applied as new grassroots production facilities are constructed.
There are still many hydrotreating units installed worldwide which produce transportation fuels containing 500-3000 ppmw sulfur. These units were designed for, and are being operated at, relatively milder conditions (e.g., low hydrogen partial pressures of 30 kilograms per square centimeter for straight run gas oils boiling in the range of 180° C.-370° C.). Retrofitting is typically required to upgrade these existing facilities to meet the more stringent environmental sulfur specifications for transportation fuels mentioned supra. However, because of the comparatively more severe operational requirements (i.e., higher temperature and pressure) needed to obtain clean fuel production, retrofitting can raise substantial issues. Retrofitting can include one or more of integration of new reactors, hydrogen partial pressure, reengineering the internal configuration and components of reactors, utilization of more active catalyst compositions, installation of improved reactor components to enhance liquid-solid contact, increase of reactor volume, and an increase of feedstock quality.
Sulfur-containing compounds that are typically present in hydrocarbon fuels include aliphatic molecules such as sulfides, disulfides and mercaptans, as well as aromatic molecules such as thiophene, benzothiophene and its long chain alkylated derivatives, and dibenzothiophene and its alkyl derivatives such as 4,6-dimethyldibenzothiophene. Aromatic sulfur-containing molecules have a higher boiling point than aliphatic sulfur-containing molecules, and are consequently more abundant in higher boiling fractions. For example, certain fractions of gas oils possess different properties. Table 1 illustrates the properties of light and heavy gas oils derived from Arabian light crude oil:
TABLE 1Composition of light and heavy gas oil fractionsFeedstock NameLightHeavyBlending Ratio——API Gravity°37.530.5CarbonW %85.9985.89HydrogenW %13.0712.62SulfurW %0.951.65Nitrogenppmw42225ASTM D86 DistillationIBP/5 V %° C.189/228147/24410/30 V %° C.232/258276/32150/70 V %° C.276/296349/37385/90V %° C.319/330392/39895 V %° C.347Sulfur SpeciationOrganosulfur Compoundsppmw45913923Boiling Less than 310° C.Dibenzothiophenesppmw10412256C1-Dibenzothiophenesppmw14412239C2-Dibenzothiophenesppmw13252712C3-Dibenzothiophenesppmw11045370
As seen in Table 1, the light and heavy gas oil fractions have ASTM (American Society for Testing and Materials) D86 85V % points of 319° C. and 392° C., respectively. Further, the light gas oil fraction contains less sulfur and nitrogen than the heavy gas oil fraction (0.95 W % sulfur as compared to 1.65 W % sulfur and 42 ppmw nitrogen as compared to 225 ppmw nitrogen).
It is known that middle distillate cuts, which boil in the range of 170° C.-400° C. contain sulfur species, such as but not limited to, thiols, sulfides, disulfides, thiophenes, benzothiophenes, dibenzothiophenes, and benzonaphthothiophenes, with and without alkyl substituents. (Hua, et al., “Determination of Sulfur-containing Compounds in Diesel Oils by Comprehensive Two-Dimensional Gas Chromatography with a Sulfur Chemiluminescence Detector,” Journal of Chromatography A, 1019 (2003) pp. 101-109). The sulfur specification and content of light and heavy gas oils are conventionally analyzed by two methods. In the first method, sulfur species are categorized based on structural groups. The structural groups include one group having sulfur-containing compounds boiling at less than 310° C., including dibenzothiophenes and its alkylated isomers, and another group including 1, 2 and 3 methyl-substituted dibenzothiophenes, denoted as C1, C2 and C3, respectively. Based on this method, the heavy gas oil fraction contains more alkylated di-benzothiophene molecules than the light gas oils.
Aliphatic sulfur-containing compounds are more easily desulfurized (labile) using conventional hydrodesulfurization methods. However, certain highly branched aliphatic molecules are refractory in that they can hinder sulfur atom removal and are moderately more difficult to desulfurize using conventional hydrodesulfurization methods.
Among the sulfur-containing aromatic compounds, thiophenes and benzothiophenes are relatively easy to hydrodesulfurize. The addition of alkyl groups to the ring compounds increases the difficulty of hydrodesulfurization. Dibenzothiophenes resulting from addition of another ring to the benzothiophene family are even more difficult to desulfurize, and the difficulty varies greatly according to their alkyl substitution, with di-beta substitution being the most difficult type of structure to desulfurize, thus justifying their “refractory” appellation. These beta substituents hinder exposure of the heteroatom to the active site on the catalyst.
Economical removal of refractory sulfur-containing compounds is therefore exceedingly difficult to achieve and, accordingly, removal of sulfur-containing compounds in hydrocarbon fuels to achieve an ultra-low sulfur level is very costly using current hydrotreating techniques. When previous regulations permitted sulfur levels up to 500 ppmw, there was little need or incentive to desulfurize beyond the capabilities of conventional hydrodesulfurization, and hence the refractory sulfur-containing compounds were not targeted. However, in order to meet the more stringent sulfur specifications, these refractory sulfur-containing compounds must be substantially removed from hydrocarbon fuels streams.
Relative reactivities of sulfur-containing compounds based on their first order reaction rates at 250° C. and 300° C. and 40.7 Kg/cm2 hydrogen partial pressure over Ni—Mo/alumina catalyst, and activation energies, are given in Table 2 (Steiner P. and Blekkan E. A., “Catalytic Hydrodesulfurization of a Light Gas Oil over a NiMo Catalyst: Kinetics of Selected Sulfur Components,” Fuel Processing Technology, 79 (2002) pp. 1-12).
TABLE 2Hydrodesulfurization reactivity of dibenzothiophene and its derivativaties4-methyl-dibenzo-4,6-dimethyl-dibenzo-NameDibenzothiophenethiophenethiopheneStructure Reactivity k@250, s−157.710.41.0Reactivity k@300, s−17.32.51.0Activation Energy28.736.153.0Ea, Kcal/mol
As is apparent from Table 2, dibenzothiophene is 57 times more reactive than the refractory 4,6-dimethyldibenzothiphene at 250° C. Although not shown, the relative reactivity decreases with increasing operating severity. With a 50° C. temperature increase, the relative reactivity of di-benzothiophene compared to 4, 6-dibenzothiophene decreases to 7.3 from 57.7.
The development of non-catalytic processes for desulfurization of petroleum distillate feedstocks has been widely studied, and certain conventional approaches based on oxidation of sulfur-containing compounds are described, e.g., in U.S. Pat. Nos. 5,910,440; 5,824,207; 5,753,102; 3,341,448 and 2,749,284, all of which are incorporated by reference.
Liquid phase oxidative desulfurization (ODS) as applied to middle distillates is attractive for several reasons. First, mild reaction conditions, e.g., temperature from room temperature up to 200° C. and pressure from 1 up to 15 atmospheres, are normally used, thereby resulting in reasonable investment and operational costs, especially for hydrogen consumption, which is usually expensive. Another attractive aspect is related to the reactivity of high aromatic sulfur-containing species. This is evident since the high electron density at the sulfur atom caused by the attached electron-rich aromatic rings, which is further increased with the presence of additional alkyl groups on the aromatic rings, will favor its electrophilic attack as shown in Table 3 (Otsuki, et al., “Oxidative desulfurization of light gas oil and vacuum gas oil by oxidation and solvent extraction,” Energy & Fuels, 14 (2000) pp. 1232-1239). However, the intrinsic reactivity of molecules such as 4,6-DMDBT should be substantially higher than that of dibenzothiophene (DBT), which is much easier to desulfurize by hydrodesulfurization.
TABLE 3Electron Density of selected sulfur speciesSulfur compoundFormulasElectron DensityK (L/(mol.min))Thiophenol5.9020.270 Methyl Phenyl Sulfide5.9150.295 Diphenyl Sulfide5.8600.156 4,6-DMDBT5.7600.0767 4-MDBT5.7590.0627 Dibenzothiophene5.7580.0460 Benzothiophene5.7390.00574 2,5-Dimethylthiophene5.716— 2-methylthiophene5.706— Thiophene5.696—
Recently, the use of cobalt and manganese based catalysts in air based oxidation of DBT type aromatic sulfur compounds into polar sulfones and/or sulfoxides has been described. A wide number of transition metal oxides, including MnO2, Cr2O3, V2O5, NiO, MoO3 and Co3O4, as well as transition metal containing compounds such as chromates, vanadates, manganates, rhenates, molybdates and niobates are described, but the most active and selective compounds were manganese and cobalt oxides. It was shown that the manganese or cobalt oxides containing catalysts provided 80% oxidation conversion of DBT at 120° C. One advantage of these catalysts is that the treatment of fuel takes place in the liquid phase. The general reaction scheme for the ODS process suggested is as follows: sulfur compound R—S—R′ is oxidized to sulfone R—SO2—R′, and the latter can decompose with heating, to liberate SO2 and R—R′, while leaving behind hydrocarbon compounds that can be utilized in various ways. A recommended temperature for the reaction is from 90° C. to 250° C. See, e.g., PCT Application No. WO 2005/116169.
High catalytic activity of manganese and cobalt oxides supported on Al2O3 in oxidation of sulfur compounds at 130° C.-200° C. and atmospheric pressure has been described by Sampanthar, et al., “A Novel Oxidative Desulfurization Process to Remove Refractory Sulfur Compounds from Diesel Fuel,” Applied Catalysis B: Environmental, 63(1-2), 2006, pp. 85-93. The authors show that, after the subsequent extraction of the oxidation products with a polar solvent, the sulfur content in the fuel decreased to 40-60 ppmw. Thiophene conversion increased with time and it reached its maximum conversion of 80-90% in 8 hours. It was shown that the trisubstituted dibenzothiophene compounds were easier to be oxidized than the monosubstituted dibenzothiophenes. The oxidative reactivity of S-compounds in diesel follows the order: trialkylsubstituted dibenzothiophene>dialkyl-substituted dibenzothiophene>monoalkyl substituted dibenzothiophene>dibenzothiophene. These results showed that the most refractory sulfur compounds in the diesel hydrodesulfurization were more reactive in the oxidative desulfurization of fuel.
U.S. Pat. No. 5,969,191, incorporated by reference, describes a catalytic thermochemical process. A key catalytic reaction step in the thermochemical process scheme is the selective catalytic oxidation of organosulfur compounds (e.g., mercaptan) to a valuable chemical intermediate (e.g., CH3SH+2O2→3 H2CO+SO2+H2O) over certain supported (mono-layered) metal oxide catalysts. The preferred catalyst employed in this process consists of a specially engineered V2O5/TiO2 catalyst that minimizes the adverse effects of heat and mass transfer limitations that can result in the over oxidation of the desired H2CO to COx and H2O.
The process described later in U.S. Pat. No. 7,374,466, incorporated by reference, involves contacting of heterocyclic sulfur compounds in a hydrocarbon stream, e.g., in a petroleum feedstock or petroleum product, in the gas phase, in the presence of oxygen with a supported metal oxide catalyst, or with a bulk metal oxide catalyst to convert at least a portion of the heterocyclic sulfur compounds to sulfur dioxide and to useful oxygenated products, as well as sulfur-deficient hydrocarbons, and separately recovering the oxygenated products from a hydrocarbon stream with substantially reduced sulfur. The catalytic metal oxide layer supported by the metal oxide support is based on a metal selected from Ti, Zr, Mo, Re, V, Cr, W, Mn, Nb, Ta, and mixtures thereof. Generally, a support of titania, zirconia, ceria, niobia, tin oxide or a mixture of two or more of these is preferred. Bulk metal oxide catalysts based on molybdenum, chromium and vanadium can be also used. Sulfur content in fuel could be less than about 30-100 ppmw. The optimum space velocity likely will be maintained below 4800 V/V/hr and temperature will be 50° C.-200° C.
The vapor-phase oxidative desulfurization of various sulfur compounds (such as: COS, or CS2, CH3SH, CH3SCH3, CH3SSCH3, thiophene and 2,5-dimethylthiophene) by use of sulfur-tolerant V2O5-containing catalysts on different supports has been taught by Choi, S., et al., “Selective Oxidesulfurization of Cl-Organosulfur Compounds over Supported Metal Oxide Catalysts,” Preprints of Symposia—American Chemical Society, Division of Fuel Chemistry, 47(1):138-139 (2002) and Choi S., et al., “Vapor-phase Oxidesulfurization (ODS) of Organosulfur Compounds: Carbonyl Sulfide, Methyl Mercaptans and Thiophene,” Preprints of Symposia—American Chemical Society, Division of Fuel Chemistry, 49(2):514-515 (2004). In these papers, the feed gas contained 1000 ppmw of COS, or CS2, CH3SH, CH3SCH3, CH3SSCH3, thiophene and 2,5-dimethylthiophene, 18% O2 in He balance. The formed products (formalin, CO, H2, maleic anhydride and SO2) were monitored by temperature programmed surface reaction mass spectrometry. It was shown that the turnover frequency for COS and CS2 oxidation varied by about one order of magnitude depending on the support, in the order CeO2>ZrO2>TiO2>Nb2O5>Al2O3—SiO2.
A common catalyst for oxidative desulfurization is activated carbon (Yu, et al., “Oxidative Desulfurization of Diesel Fuels with Hydrogen Peroxide in the Presence of Activated Carbon and Formic Acid,” Energy & Fuels, 19(2) pp. 447-452 (2005); Wu, et al., “Desulfurization of gaseous fuels using activated carbons as catalysts for the selective oxidation of hydrogen sulfide,” Energy and Fuels, 19(5) pp. 1774-1782 (2005)). The application of this method allows removal of hydrogen sulfide from gaseous fuels at 150° C. by oxidation with air (Wu, 2005) and also sulfur removal from diesel fuels using hydrogen peroxide (Yu, 2005). The higher adsorption capacity of the carbon, the higher its activity in the oxidation of dibenzothiophene.
Various catalytic desulfurization processes are known. See, e.g., U.S. Patents Turbeville, et al. U.S. Pat. No. 7,749,376, Courtv, et al. U.S. Pat. No. 4,596,782, Yoo, et al. U.S. Pat. No. 3,945,914, and Hoover, et al. U.S. Pat. No. 2,640,010, all of which are incorporated by reference.
Nonetheless, demand remains for additional efficient and effective process and apparatus for desulfurization of hydrocarbon fuels to an ultra-low sulfur level.
U.S. Pat. Nos. 8,920,635 and 8,906,227 describe gas phase oxidative desulfurization processes for gas oils over an oxidation catalyst. However, these patents do not teach demetallization or desulfurization of residual oil.
Unlike light crude oil fractions, heavy crude oil fractions contain metals in part per million quantities, which originate from crude oil. Crude oil contains heteroatom contaminants such as nickel, vanadium, sulfur, nitrogen, and others in quantities that can adversely impact the refinery processing of the crude oil fractions, e.g., by poisoning catalysts. Light crude oils or condensates contain such contaminants in concentrations as low as 0.01 W %. In contrast, heavy crude oils contain as much as 5-6 W %. The nitrogen content of crude oils can range from 0.001-1.0 W %. The heteroatom content of typical Arabian crude oils are listed in Table 4 from which it can be seen that the heteroatom content of the crude oils within the same family increases with decreasing API gravity, or increasing heaviness.
TABLE 4Composition and properties of various crude oilsPropertyASL*AEL*AL*AM*AH*Gravity, °51.439.53331.127.6Sulfur, W %0.051.071.832.422.94Nitrogen, ppmw70446106414171651RCR, W %0.511.723.875.277.62Ni + V, ppmw<0.12.9213467*ASL—Arab Super Light; AEL—Arab Extra Light; AL—Arab Light; AM—Arab Medium and AH—Arab Heavy;W % is percent by weight;ppmw is parts per million by weight.
These crude oil data were further analyzed, and the metal distribution of various cuts were determined. Table 5 illustrates the metal distribution of the Arab light crude oil fractions.
TABLE 5Metal distribution of Arab light crude oilFractionVanadium, ppmwNickel, ppmw204° C.+185260° C.+195316° C.+309371° C.+3610427° C.+4312482° C.+5717
As seen in Table 5, the metals are in the heavy fraction of the crude oil, which is commonly used as a fuel oil component or processed in residual hydroprocessing units. The metals must be removed during the refining operations to meet fuel burner specifications or prevent the deactivation of hydrodesulfurization catalysts downstream of the process units.
In a typical petroleum refinery, crude oil is first fractionated in an atmospheric distillation column to separate and recover sour gas and light hydrocarbons, including methane, ethane, propane, butanes and hydrogen sulfide, naphtha (36-180° C.), kerosene (180-240° C.), gas oil (240-370° C.), and atmospheric residue, which is the remaining hydrocarbon fraction boiling above 370° C. The atmospheric residue from the atmospheric distillation column is typically used either as fuel oil or sent to a vacuum distillation unit, depending on the configuration of the refinery. The principal products of vacuum distillation are vacuum gas oil, which comprises hydrocarbons boiling in the range 370-565° C., and the vacuum residue consisting of hydrocarbons boiling above 565° C. The metals in the crude oil fractions impact downstream process including hydrotreating, hydrocracking and FCC.
Naphtha, kerosene and gas oil streams derived from crude oils or from other natural sources such as shale oils, bitumens and tar sands, are treated to remove the contaminants, e.g., mainly sulfur, whose quantity exceeds specifications. Hydrotreating is the most common refining process technology employed to remove the contaminants. Vacuum gas oil is typically processed in a hydrocracking unit to produce naphtha and diesel or in a fluid catalytic cracking unit to produce gasoline, with LCO and HCO as by-products. The LCO is typically used either as a blending component in a diesel pool or as fuel oil, while the HCO is typically sent directly to the fuel oil pool. There are several processing options for the vacuum residue fraction, including hydroprocessing, coking, visbreaking, gasification and solvent deasphalting.
Reduction in the amount of sulfur compounds in transportation fuels and other refined hydrocarbons is required in order to meet environmental concerns and regulations. Removal of contaminants depends on their molecular characteristics; therefore, detailed knowledge of the sulfur species in the feedstock and products is important for the optimization of any desulfurization process. Numerous analytical tools have been employed for sulfur compounds speciation. Gas chromatography (GC) with sulfur-specific detectors is routinely applied for crude oil fractions boiling up to 370° C. The use of ultra-high resolution Fourier transform ion cyclotron resonance (FT-ICR) mass spectrometry has recently been advanced as a powerful technique for the analysis of heavy petroleum fractions and whole crude oils. Use of this methodology is described in, e.g., Hughey. C. A., Rodgers, R. P., Marshall, A. G., Anal. Chem. 2002, 74, 4145-4149; Muller, H., Schrader, W., Andersson, J. T., Anal. Chem., 2005; 77, 2536-25431 and Choudhary, T. V. Malandra, J., Green J., Parrott, S., Johnson, B., Angew. Chem., Int. Ed. 2006, 45, 3299-3303.
From the above discussion, it is apparent that it would be desirable to upgrade heavy crude oil fractions, bottoms, or residual oil by both removing specific undesirable metal compounds at an early stage of processing and that the demetalized stream can be desulfurized.
There is a large body of prior art on the hydrodemetallization of petroleum products. U.S. Pat. No. 8,491,779, incorporated by reference, teaches the integration of hydrodemetallization (“HDM” hereafter) and hydrodesulfurization (“HDS” hereafter).
The HDM step is carried out in the presence of a catalyst and hydrogen. The hydrogen that is used can come from a downstream step. The HDM is carried out at 370-415° C., pressure of 30-200 bars. Following the HDM step, effluent streams are subjected to HDS. There is no suggestion of integration of ODS.
Also, see U.S. Pat. No. 5,417,846, incorporated by reference, teaching HDM, as well as U.S. Pat. Nos. 4,976,848; 4,657,664; 4,166,026; and 3,891,541, all of which are incorporated by reference.
While some of these patent describe the integration of HDM and HDS, none suggest integration of ODS.
There is also a large body of prior art on ODS, but without integration with other processes
Published U.S. Application No. 2012/0055845 to Bourane, et al., now also U.S. Pat. No. 9,574,143, also incorporated by reference, teaches ODS, as a separate process, not integrated with delayed coking of residual oil. Also see Published U.S. Application No. 2017/0190641 to Koseoglu, et al., also incorporated by reference; Published U.S. Application No. 2018/0029023 to Koseoglu, et al., also incorporated by reference, (these published U.S. applications correspond to WO 2017 120130 and WO 2018 022596, respectively); and also U.S. Pat. Nos. 9,663,725; 9,598,647; 9,574,144; and 9,574,142, all incorporated by reference. Also see U.S. Pat. Nos. 9,464,241 and 9,062,259, and as well as Gao, et al., Energy & Fuels, 23:624-630 (2009). These references all discuss ODS processes using various catalysts and methodologies.
U.S. Pat. No. 8,980,080 to Koseoglu, et al., incorporated by reference, teach process where liquid phase ODS is used prior to solvent deasphalting, both of which are contrary to the invention described herein.
U.S. Pat. No. 8,790,508 to Koseoglu, et al., also incorporated by reference, also teaches liquid phase ODS. Also, in contrast to the current invention, this patent teaches that the liquid phase ODS and solvent deasphalting occur simultaneously.
Published U.S. Patent Application 2009/0242460 to Soloveichik, et al., incorporated by reference, teaches ODS at a very low temperature, i.e., 25-150° C. The current invention proceeds with gas phase ODS at a temperature above 400° C., with a very specific catalyst, as described infra.
It is therefore a principal object of the present invention to provide a novel method of treating a hydrocarbon feedstock, such as residual oil, to substantially reduce the content of undesired metal, and sulfur compounds. This is accomplished via an integrated process by which the feed, such as residual oil, is subjected to hydrodemetallization, and gas phase oxidative desulfurization. Other steps, such as HDS and/or hydrocracking may be added, but are not required. These optional steps may take place before or after gas phase ODS, but the HDM step occurs first.